Method and apparatus for single-trip wellbore treatment

ABSTRACT

The apparatus consists of a tubular housing carried into the well on a workstring. A series of spaced isolation modules is provided for each zone and carried into the well on a tubular conduit. The first, or most downstream module includes first and second sealing mechanisms to isolate the first zone to be treated. A full bore valve is provided that is activated to closed position by an activating component in response to a source of a first level of pressure to isolate the first zone from other parts of the well bore. A port within the housing is initially blocked but selectively opened concurrently with the activation of the first sealing means to manipulate the second sealing mechanism to fully isolate the selected zone and the module. As the module is activated, a second full bore valve is activated to seal the interior of the housing upstream of the first module by manipulation of the tubular string.

CROSS-REFERENCE TO RELATED APPLICATION AND CLAIM OF PRIORITY

This is a utility application claiming priority from U.S. provisionalpatent application No. 61/305,621, filed Feb. 18, 2010, entitled “Methodand Apparatus For Single-Trip Wellbore Treatment”, Gregg W. Stout,inventor.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to apparatus and methods for oil and gaswells to enhance the production of subterranean wells, either open holeor cased hole, and more particularly to improved multizone stimulationsystems.

2. Brief Description of the Prior Art

Wells are drilled to a depth in order to intersect a series offormations or zones in order to produce hydrocarbons from beneath theearth. The drilled wells are cased and cemented to a planned depth andthen may cased and cemented or a portion left open hole. Producingformations intersected with the well bore in order to create a flow pathto the surface. Stimulation processes, such as fracing or acidizing orother chemicals or proppants, are used to increase the flow ofhydrocarbons through the formations. The formations may have reducedpermeability due to mud and drilling damage or other formationcharacteristics. In order to increase the flow of hydrocarbons throughthe formations, it is desirable to treat the formations to increase flowarea and permeability. This is done most effectively by setting eitheropen-hole packers or cased-hole packers at intervals along the length ofthe wellbore. These packers isolate sections of the formations so thateach section can be better treated for productivity. Between the packersis a frac port and in some cases a sliding sleeve or a gravel packscreen with sliding sleeves. In order to direct a treatment fluidthrough a frac port and into the formation, a seat may be placed eitheron top of a sliding sleeve or below a frac port. A ball or plug may bedropped to land on the seat in order to direct fluid through the fracport and into the formation.

One method places a series of ball seats below the frac ports with eachseat size accepting a different ball size. Smaller diameter seats are atthe bottom of the completion and the seat size increases for each zoneas you go up the well. For each seat size there is a ball size so thesmallest ball is dropped first to clear all the larger seats until itreaches the appropriate seat. In cases where many zones are beingtreated, maybe as many as 20 zones, the seat diameters have to be veryclose. The balls that are dropped have less surface area to land on asthe number of zones increase. With less seat surface to land on, theamount of pressure you can put on the ball, especially at elevatedtemperature, becomes less and less. This means you can't get adequatepressure to frac the zone or the ball is so weak, the ball blows throughthe seat. Furthermore, the small ball seats reduce the I.D. of theproduction flow path which creates numerous other problems. The smallI.D. prevents re-entry of other downhole devices, i.e., plugs, runningand pulling tools, shifting tools for sliding sleeves, perforating gunsize (smaller guns, less penetration), and of course production rates.In order to remove the seats, a milling run is needed to mill out allthe seats and any balls that remain in the well.

The size of the ball seats and related balls limits the number of zonesthat can be treated in a single trip. It would be advantageous toreplace the use of the ball seats with a workstring actuated isolationdevice, such as a flapper or rotating ball, to allow the treatment of anunlimited number of zones in a single trip.

Another method is that disclosed in U.S. Pat. No. 7,543,634 B2. Thismethod places sleeves in the I.D. of the tubing string. These sleevescover the frac ports and packers are placed above and below the fracports. Varying sizes of balls or plugs are dropped on top of the sleevesand when pressing down the tubing, the pressure acts on the ball and theball forces the sleeve downward. Once again you have the restriction ofthe ball seats and theoretically, and most likely in practice, when theball shifts the sleeve downward, the frac port opens and allows theforce due to pressure diminish off before the sleeve is fully opened. Ifthe ball and sleeve remain in the flow path, the flow path is restrictedfor the frac operation.

It would be advantageous to have a system that had no ball seats thatrestrict the I.D. of the tubing and to eliminate the need to spend thetime and expense of milling out the ball seats, not to mention thedebris created by the milling operation. Also it would be beneficial tohave a system that fully opens the sliding sleeve before sleeveactivating pressure bleeds down, to assure the sleeve is fully openedbefore treating the formation.

Furthermore, it would be greatly advantageous to eliminate the time andlogistics required for dropping numerous balls into the well, one at atime, for each zone in the well to be treated.

In some well completions the operator may want to perforate below thepacker. If the completion has small I.D. ball seats, the maximum O.D. ofthe perforating guns must drift through the ball seats. Small I.D. ballseats mean small O.D. perforating guns. It is well known in the industrythat the smaller the O.D. of the perforating gun, the less thepenetrating performance of the gun. It would be very advantageous to beable to run the largest O.D. gun possible inside of the tubing toachieve the greatest penetration through the tubing and casing walls toget the deepest penetration into the formation.

Some zones in the formation are very close together or water is nearby.Fracturing programs sometimes want to limit the length of the zone to betreated so isolation packers with sliding sleeves need to be set veryclose together. To achieve this it would be beneficial to have a shortcompact packer-sliding sleeve assembly where several assemblies could bestacked closely together. One of the advantages of the present inventionis to integrate to components of the packer and sliding sleeve toproduce a reduced overall length apparatus to address the completion ofclosely positioned zones.

SUMMARY OF THE INVENTION

A single trip multizone well treating method and apparatus provides ameans to progressively stimulate individual zones through a cased oropen hole well bore. The need to drop and mill balls and seats for eachzone or run hydraulic control lines from the surface to actuate a seriesof isolation devices has been eliminated. Also, the I.D. restrictioncreated by balls and seats has been eliminated to provide a full borecompletion. The full bore completion allows use of larger perforatingguns when thru-tubing perforating is desired. A unique feature of thissystem is that the operator can progressively treat each zone up thehole by moving the workstring up and down a short distance to release aflapper valve selectively for each zone. Applied pressure to the flapperboth opens a sliding sleeve and sets a packer and then shifts theflapper below the frac port so a pumping treatment can commence. Theapparatus is presented as a “Frac Module” that consists of three majorcomponents, a packer, a sliding sleeve, and a workstring actuated fluidisolation device which are integrated together in an assembly that wouldbe shorter in length for closely placed zones. One Frac Module is usedper zone and the frac module is stacked with tubing spacers through allzones that need treatment and zonal isolation.

Stated a slightly different way, the invention provides a full bore,single trip multizone subterranean well treating apparatus. Theapparatus is carried into the well on a tubular workstring, which mayalso be later used as the production tubing. A tubular housing isdefined on the workstring and includes a central first fluid passagewaytherethrough. A plurality of treatment modules are provided on thehousing, each module being pre-determinedly spaced on the housing foroperable alignment with a zone in the well. Each module includes atubular housing member with a treatment fluid port therein and a controlchamber selectively communicable with the port. First and second spacedsealing mechanisms, such as packers, are provided to isolate theselected zone from other portions of the well. A first full bore valvingmechanism is initially positioned in the housing in open position and isselectively activatable to closed position to block fluid under pressurefrom being transmitted within the tubular housing and across the valvingmember. Activation means are provided for the first valving means andresponsive to a first level of pressure applied through the workstringto open the port and place a chamber in fluid communication with a fluidpassageway within the housing. Pressure within the housing member abovethe first level further activates the a first sealing means, or packer,to set position. A second fluid flow passageway in the housing includesa blocked port opening to the interior of the housing, and the port isopened during activation of the first sealing means, or packer. A secondactivation means, such as a sleeve, is responsive to a pressure level insaid tubing in excess of that required to set the second sealing meansand to open a treatment port. In each of the modules upstream of themodule used to isolate the first zone to be treated, there is provided afull bore valve in initial open position but shiftable to closedposition by mechanical manipulation of the workstring to block fluidflow across the valve.

This invention provides an improved multizone stimulation system toimprove the conductivity of the well formations with reduced rig timeand no milling. The equipment for all zones can be conveyed in singleworkstring trip and frac units can stay on location one time to treatall zones.

In a preferred embodiment, work string weight is set down and pressureis applied to the lowermost isolation device, such as a flapper. Theflapper is released and allowed to close. The flapper is mounted on asleeve that is shear pinned. A low initial pressure shifts the flapperand sleeve downward to open a pressure port. Tubing pressure enters theport to shift the sliding sleeve downward to an open position to uncoverthe frac port and simultaneously begin setting a packer locatedimmediately above the frac port. The setting motion within the packeropens a port to the tubing to allow tubing pressure to travel up acontrol line to the next upper zone to activate a flapper releasemechanism, but the next upper flapper does not close at this point.Tubing pressure is increased to fully set the packer and theflapper/sleeve shears and shifts downward to a position below the fracport. In this position, the flapper/sleeve then rests on top of thesliding sleeve. With the frac port now fully open, the first zone istreated while the workstring remains in the set-down position. After thestimulation of the lower zone, the work string is picked up a shortdistance to release the flapper only in the next upper zone so the nextupper zone can be treated. All upper zones are then progressivelytreated using the same process. A set-down and pickup type packer can beused above all of the frac Modules and above the uppermost set ofperforations, assuming all zones were perforated initially. A productionpacker can be run in the string above the set-down packer, if desired,and be set after all zones are completed. Once the well is nippled-upthe well can be put on production. If flapper valves are used, they willopen and allow flow. It is also possible to make a trip into the welland break the frangible flapper discs. If sliding sleeves are used,shifting tools can be run in to open or close the sliding sleeves.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1 a, 1 b, and 1 c placed end-to-end make up a schematic view ofthe present invention.

FIG. 2 is a schematic view of three Frac Modules assembled in tandem ina well completion.

FIG. 3 is a schematic view of three cased and perforated zones isolatedwith a completion string of tools.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

With reference to FIG. 1 a, a schematic of the present invention shows a90 degree lengthwise cross-section of the apparatus. This portion of theapparatus is the packer with only a packing element. A packer may beused that has a slip system added and a packer may be used that has arelease devise added. Top sub 1 has a connecting thread at the top end2, an internal thread 3, and o-ring seals 4 and 5. Shear Screws 6shearably connect Top Sub 1 to Shear Ring 7. Shear Screws 8 shearablyconnect the Top Sub 1 to Push Sleeve 12. The hole 9 communicates withhole 13. A fitting 10 seals in hole 9 and also connects to hydrauliccontrol line 11. Hole 13 is located inside of Flow Body 14. Seals 15,16, 4, 5 seal between the Top Sub 1 and the Flow Body 14 to isolate flowpaths 9 and 13 from pressure inside the tool 22 or outside the tool 23.Port 20 has Seals 17 and 18 to seal off Port 20 with Push Sleeve 12.Seals 18 and 19 with Push Sleeve 12 seal off port 21 to prevent pressurein tool 22 from entering port 20. Seals 24 and 25 in Flow Body 14, sealwith Packer Mandrel 26.

Thread 27 attaches Flow Mandrel 14 to Packer Body 26. Packing Element 28rests on the Packer Mandrel 26 and between faces 30 and 31. Gage Ring 29is attached to Piston 32 with thread 37. Piston 32 slides between PistonHousing 38 and Mandrel 26 and seals 33 and 34 act as piston seals. BodyLock Ring 35 threadably engages Piston Housing threads 44 so items 35and 44 move together. Body Lock Ring 35 sets on smooth S surface 45 andat a later point in time engages Piston threads 46. Screw 36 preventsrotation of Body Lock Ring 35 relative to Piston 32. Connector 43 isattached to Mandrel 26 with thread 39 and seals 41 and 42 create a sealbetween items 25 and 43. Hole 40 in Connector 43 communicates withPiston 32.

With reference to FIG. 1 b, Connector 43 and hole 40 continue in theapparatus. Lower Pickup Sleeve 49 is attached to Connector 43 withthread 53 and seals 47 and 48 seal between the items 43 and 49. Hole 40communicates with chamber 54. Release Sleeve 55 slides within Connector43 and seal surface 52 seals at O-rings 50 and 51. Upper Pickup Sleeve56 slides inside of Lower Pickup Sleeve 49. Surfaces 57 and 58 engageduring pickup while surfaces at location 70 make contact duringset-down.

Dynamic Seals 59, 60, and Static Seals 61, and 62 seal on seal surface63 of the Upper Pickup Sleeve 56. Upper Pickup Sleeve 56 is connected toHousing 65 with threads 64.

Housing 65 attaches to Frac Port Housing 66 with thread connection 67and seals 68 and 69 seal between items 65 and 66. Seals 72 and 73 arepositioned on Release Sleeve 55 and form a seal on Frac Port Housing 66at seal surface 71. Shear Ring 74 is shearably connected to ReleaseSleeve 55 with shear screws 75. Shear Ring 74 is trapped in pocket 76 soRelease Sleeve 55 can't move up or down. Shifting Profile 77 inside ofRelease Sleeve 55 engages a shifting tool (not shown) so that theshifting tool can engage the profile 77 and move the Release Sleeve 55upward.

The bottom of Release Sleeve 55 has a finger 78 attached. The finger 78engages the Flapper 79 at location 84. The Flapper 79 is affixed toFlapper Seat Sleeve 81 with axle 80 so the Flapper 79 is free to pivotaround axle 80. Flapper Seat Sleeve 81 is attached to Seat Housing 83with shear pin 82. Flapper Seat Sleeve 81 can slide downward into SeatHousing 83 until faces 84 and 85 come into contact. Seat Housing 83 isshear pinned to Frac Port Housing 66 with Shear Pins 86. Seals 87, 88,89, and 90 are positioned in Barrel 91 and prevent pressure from movingfrom location 22 to location 23 or vice-versa.

One or more Frac Ports 92 are located in Frac Port Housing 66. The ports92 go completely through the wall of the Frac Port Housing 66. The FracPort Housing has gun drilled hole 93 and 94 that do not intersect theFrac Ports 92 or Shear Screw hole 86. Gun drilled hole 93 and 94 areisolated from each other by plug 95 and seals 96, 97, 98, 99, and 102.Port 100 communicates with gun drilled hole 93 and Port 101 communicateswith gun drilled hole 94, or vice-versa.

Gun Drilled Hole 93 communicates with chamber 103 and acts on seals 104and 105 located inside of Housing 65 and Release Sleeve 55. Seals 104and 105 are located on the I.D. and O.D. for Shift Piston 106.Therefore, pressure in gun drilled hole 93 acts on Shift Piston 106 andis isolated from pressures 22 and 23.

Shift Piston 106 is shearably attached to Upper Pickup Sleeve 56 withshear pin 111. Expanding Lock Dogs 107 and 109 are located in retainingslots on Shift Piston 106. Lock Dog 107 is designed to engage in groove108 inside of Lower Pickup Sleeve 49 and Lock Dog 109 is designed toengage in groove 110 on the O.D. of Release Sleeve 55. Locking Keys 112fit into slots 115 that are located in Upper Pickup Sleeve 56. TheLocking Keys 112 have teeth that expand into the I.D. thread profile 114of Lower Pickup Sleeve 49. Extended portion 113 of Shift Piston 106slides under Locking Keys 112 in order to expand and engage the teethinto profile 114 thus locking the Lower Pickup Sleeve 49 to the UpperPickup Sleeve 56 during the run-in configuration.

With reference to FIG. 1 c, note the continuation of gun drilled holes93 and 94 in Frac Port housing 66. In this figure, Gun Drilled Hole 93communicates with control line 116 which attaches control line 117 whichcommunicates with Shift Piston 106. Control Line 117 becomes the samecontrol line as Control Line 11 in FIG. 1 a so that Frac Modules in alower zone can act on Shift Piston 106.

Gun Drilled Hole 94 communicates with chamber 118 and chamber 118 isadjacent to Sliding Sleeve Piston 121. The Sliding Sleeve Piston 121 ispositioned between Frac Port Housing 66 and Sliding Sleeve 124 and sealsbetween the two with seals 119 and 120. The Sliding Sleeve Piston 121 isshearably attached to Sliding Sleeve 124 with Shear Screws 122. TheSliding Sleeve Piston 121 houses a Lock Ring 123 which engages shoulder127. Chamber 128 is below the Sliding Sleeve Piston 121 and communicateswith ports 129 which communicate with pressure 23. In summary, port 101communicates with chamber 118 to communicate with Sliding Sleeve Piston121 and the lower side of the Piston communicates with pressure 23.

Frac Port Housing 66 is connected to Sleeve Housing 130 with thread 131.Bottom Sub 135 is connected to Sleeve Housing 130 with thread 132 andseals 133 and 134 create a seal between the two. The Bottom Sub 135 haspin thread 136 facing down.

Sliding Sleeve 124 always isolates chamber 128 from pressure 22 withupper and lower seals 125 and 126. The Sliding Sleeve 124 has collets138 and 139 machined into the sleeve. These collets either engage inrecess 144 or recess 143 to hold the Sliding Sleeve 124 in either theopen or closed position. Anti-rotation Keys 137 slide in slot 130 andset in slots 145 located in the Sliding Sleeve 124. Key 137 shoulder 141engages Bottom Sub 135 shoulder 142 to limit downward movement ofSliding Sleeve 124 so that Collets 138 and 139 are not loaded incompression. Collets 138 and 139 engage a shifting tool, not shown, usedto either shift the Sliding Sleeve 124 open or closed.

With reference to FIG. 2, Frac Module 146 is comprised of the apparatusdescribed in the combination of FIGS. 1 a, 1 b, and 1 c. Thisillustration shows three Frac Modules 146 a, 146 b, and 146 c placedaround producing zones 147 and 148 and inside casing 149 with the casingsurrounded by cement 150. Perforations 151 and 152 are in communicationwith the Frac Port Windows 92 shown in FIG. 1 b. Packing Elements 153seal on the I.D. of casing 149 in order to isolate zones 147 and 148from each other. Obviously, this can be done on many zones located inthe well bore. Control lines 117 allow pressure communication from FracModule 146 c to Frac Module 146 b and then from Frac Module 146 b toFrac Module 146 a and so on for every zone to be treated.

Description of Preferred Operation

With reference to the example in FIG. 3, a typical completion is shownbut many variations of this occur as know by those who are familiar withthe variations that occur in configuring well completions.

A well has been drilled, cased, cemented, and perforated, although thissystem may be used in open hole completions with selection of theappropriate packers. Casing 149 is shown in this example withperforations 151, 152, and 154 in the casing. A sump packer 155 isproperly located and set below the lowermost zone 154.

A “completion string” is run into the well consisting of a Locator SnapLatch Seal Assembly 156, Tubing Spacer 160, Frac Module 146 c, TubingSpacer 159, Frac Module 146 b, Tubing Spacer 159, Frac Module 146 a,Tubing Spacer 161, Service/Production Packer 157, and releasable workstring 158 where a production string can be run to replace to workstringat a later date in the completion. The length of Tubing Spacers 159 and160 are made to position the Frac Modules 146 between the producingzones 162, 163, and 164. The Service/Production Packer 158 can be of thestraight pick-up and set-down style where no rotation is required tomove the packer up the hole and re-seal.

The single trip completion string is landed in sump packer 155. Thelocation of Sump Packer 155 was based on logs of the zones so that allequipment could be spaced out properly. Therefore, by locating thecompletion assembly on the Sump Packer 155, all Frac Modules 146 will beproperly positioned in the well. Snap Latch Seal Assembly 156 can beused to verify position of the system before setting any of the abovepackers. The Locator Snap Latch Seal Assembly 156 seal in the sumppacker 155 and will locate on the bottom of the Sump Packer, although“top of the packer” snap latch seal assemblies can be used as well. TheLocator Snap Latch Seal Assembly 156 is designed to allow pulling of theWork String 158 to get a load indication on the Sump Packer 155 and thensnap back in and put set-down weight on the Sump Packer 155. The loadrequired to snap out is recorded so an operator can know how much topull with the workstring before snapping out. Collets on the LocatorSnap Latch Seal Assembly 156 can be designed to snap at specified loads.The above steps are common in the art of completing wells.

To explain operation of the Frac Modules, this discussion will beginwith stimulation of the lower-most zone 164. The lowermost Frac Module146 c is assembled slightly different from all the above frac Modules146 b, 146 a, and 146 z, z being any number of zones. In Frac Module 146c, referring to FIG. 1 b, the Flapper 79 will be installed in thereleased position, i.e., finger 78 will be disengaged from location 84,so the Flapper 78 is free to go to the closed position against FlapperSeat Sleeve 81 and also be free to allow fluid from below the Flapper 79to open the Flapper 79 to allow the work string 158 to fill with wellfluid during tripping into the well and stinging into Sump Packer 155with Locator Snap Latch Seal Assembly 156. Also control line hole 93 isplugged at fitting 116.

Reference Point to Repeat Process

After set-down weight is placed on the sump packer 155, maybe 10,000 to20,000 pounds, the Service Packer 157 will be set with set-down weight,and the Hydrils can be closed on the workstring 158. Frac lines can beattached at the surface and pressure can be applied down the workstring158 against the Flapper 79 in Frac Module 146 c.

Referring to FIG. 1 a, 1 b, and 1 c it will be explained 1) how thepacking element 28, or a packing element plus a slip system (not shown),is actuated, and 2) how the Sliding Sleeve 124 is opened, and 3) how theFlapper/Seat Assembly, items 79,80,81,83, moves downward below the FracPort 92 and lands on top of the Sliding Sleeve 124, and 4) how the LowerPickup Sleeve 49 is unlocked, and 5) how the Flapper 79 in Frac Module146 b, in the next upper zone 163, is put into the prepare for releasemode.

In operation, the workstring 158 pressure 22 acts on the closed Flapper79 in Frac Module 146 c. Shear pin 82 is set at a lower shear value thanshear screw 86 so pressure 22 acts on seal 98 and Flapper 79 and FlapperSeat Sleeve 81 causing Shear Pin 82 to shear. Face 82 moves downward tocontact face 85 so that the Flapper Seat Sleeve 81 shifts below ports100 and 101. Pressure 22 travels thru port 101 and into Gun Drilled Hole94 to act on Sliding Sleeve Piston 121. Hole 94 is plugged with plug 95so pressure only acts on piston 121. The piston 121 leads shear screw122 which loads Sliding Sleeve 124 and shifts the Sliding Sleeve 124downward to the full open position where the shoulder 141 of Key 137contacts Bottom Sub shoulder 142. Frac Port 79 is now open and pressures22 and 23 communicate.

Pressure 22 also travels through port 100 and up Gun Drilled Hole 93 toact on seals 104 and 105 of Shift Piston 106 to shear pins 111 and moveShift Piston 106 upward. Upward movement of Shift Piston 106 releasesLocking Keys 112 so that Lower Pickup Sleeve 49 and Upper Pickup Sleeve56 are free to move until surfaces'57 and 58 make contact. Although,surfaces 57 and 58 will not make contact at this time because theoperator has put set-down weight on the “completion string” and alsobecause internal pressure 22 will not pump the tool open, or faces 57and 58 apart, because seals 50,51, 72, and 73 on Release Sleeve 55balance the effects of internal pressure 22. As pressure 22 continues toact on Piston 106, Piston 106 continues to move upward until ExpandingLock Dogs 107 engage groove 108 and so Piston 106 is now locked to LowerPickup Sleeve 49 and they will move together. Simultaneously, Lock Dog109 engages groove 110 located in Release Sleeve 55. The shoulder 166 ofLock Dog 109 does not push on shoulder 165 of groove 110 of the ReleaseSleeve 55 at this time because shoulder 168 of lock dog 107 contactsshoulder 165 of groove 108 of the Lower Pickup Sleeve 49.

In Frac Module 146 c, the piston length is such that when Piston 106 islocked in groove 108, pressure 22 is allowed to pass seal 104, move intochamber 54, and travel up hole 40 of Piston Housing 38. Pressure 22 cannow act on seals 33 and 34 of Piston 32 to begin setting the packer orpacking element 28. The Piston 32 causes face 31 of the Gage Ring 29 tobegin compressing packing element 28 against face 30 of Push Sleeve 12.Compressive loads to compress packing element 28 can vary from as low as10,000 pounds up to 50,000 pounds depending on the casing size and typeof packer. This load is transmitted into Push Sleeve 12 to shear pins 8and surface 30 moves up until Push Sleeve face 170 contacts Shear Ring 7at face 171. At this point, recess 172 of Push Sleeve 12 allows pressure22 to enter port 21, travel through recess 172 and into port 20 and intogun drilled hole 13. Gun drilled hole 13 is isolated with seals4,5,15,16 and connects to hole 9 in Top Sub 1. Hole 9 has connector 10that connects control line 11 which is the same as control line 117 thattravels up to Frac Module 145 b, see FIG. 3, and connects to fitting 116and travels into hole 93, see FIG. 1 c. Pressure 22 travels all the wayup to Shift Piston 106 located in Frac Module 146 b.

In Frac Module 146 b, pressure 22 acts on seals 104 and 105 of ShiftPiston 106 to shear pins 111 and move Shift Piston 106 upward. Upwardmovement of Shift Piston 106 releases Locking Keys 112 so that LowerPickup Sleeve 49 and Upper Pickup Sleeve 56 are free to move untilsurfaces 57 and 58 make contact.

Although in Frac Module 146 b, surfaces 57 and 58 will not make contactat this time because the operator has put set-down weight on the“completion string” and also because internal pressure 22 will not pumpthe tool open, or faces 57 and 58 apart, because seals 50, 51, 72, and73 on Release Sleeve 55 balance the effects of internal pressure 22. Aspressure 22 continues to act on Piston 106, Piston 106 continues to moveupward until Expanding Lock Dogs 107 engage groove 108 and so Piston 106is now locked to Lower Pickup Sleeve 49 and they will move together.Simultaneously, Lock Dog 109 engages groove 110 located in ReleaseSleeve 55. The shoulder 166 of Lock Dog 109 does not push on shoulder165 of groove 110 of the Release Sleeve 55 at this time because shoulder168 of lock dog 107 contacts shoulder 165 of groove 108 of the LowerPickup Sleeve 49. In this Frac Module the length of Shift Piston 106does not allow pressure 22 to pass seals 104 and 105, therefore thepacker in Frac Module does not begin to set until workstring pickupoccurs that allows pressure 22 to pass the seals 104 or 105 to getpressure to the packer setting piston. At this point the 146 b FracModule has been prepared for pickup to release the Flapper 79.

Going back to Frac Module 146 c, pressure 22 is increased against theFlapper79 until packer setting load increases enough to shear Screws 6in Ring 7. Push Sleeve 12 moves upward until faces 30 and 169 line up tocreate an anti-extrusion surface for packing element 28. Also, port 21is isolated with seals 18 and 19. Pressure 22 is increased until fullsetting pressure 22 of the packer is reached. Full setting pressure 22is controlled by Shear screws 86 that engage Seat Housing 83.

At this point, the Sliding Sleeve is fully opened and the packer isfully set and the upper Frac Module has an activated Flapper Releasesleeve 55.

Pressure 22 is increased until Shear Screws 86 shear and the FlapperAssembly 79, 80, 81, 83 and related seals and shear pins, shift downwardbelow the Frac Port 92 and set on top of Frac Sleeve 124 at a positionbelow the bottom edge of the Frac Port windows. The flow path to andthru the Frac Ports is now fully open and zone 164 is ready forstimulation.

Once the stimulation is complete, it's time to treat the next upper zone163. The workstring is picked up a distance “X”. This is when shoulders57 and 58 make contact and during the movement thru distance “X” LockDog Shoulder 166 engages Release sleeve shoulder 165 which shiftsRelease Sleeve 55 upward. The Release Sleeve Finger 78 disengagesFlapper 79 and allows Flapper 79 to close. The operator is now ready tobegin operations on zone 163 as described above beginning at Referencepoint to repeat process.

The above process repeats for all zones. The pickup length “X” can bemeasured at the rig floor by marking pipe for each zone. The occurrenceof length “X′ at the surface verifies that the Flapper 79 has beenreleased in each zone. As zones are treated, “X” increases at the rigfloor. If a Flapper 79 does not release, the Release Sleeve 55 may beshifted upward to release the Flapper 79 using a shifting tool thatlocates in profile 77 of Release Sleeve 55.

1) A full bore single trip multizone subterranean well treatingapparatus, carriable into the well on a tubular workstring, saidapparatus comprising: (a) a tubular housing carried on said workstringand including a first fluid passageway therethrough; (b) a plurality oftreatment modules in securing relationship with said workstring, eachsaid module being pre-determinedly spaced on said housing for operablealignment with a zone in said well to be selectively treated, each saidmodule including: (1) a tubular housing member including a treatmentfluid port therein and including a selectively communicable controlchamber; (2) first and second sealing mechanisms on said tubular housingfor isolating a selected first zone to be treated from another portionof said well; (3) a first full bore valving mechanism initiallypositioned within said housing in a full bore open position andselectively activatable to a closed position blocking fluid underpressure from being transmitted within said tubular housing and acrosssaid valving member; (4) first activation means for said first full borevalving means initially responsive to a first level of fluid pressureapplied through said workstring and into said housing member andshiftable from a first inactive position to a second activated position,whereby said port is opened to place said chamber in fluid communicationwith said first fluid passageway of said tubular housing, and furtherwhereby fluid pressure within said housing member above the said firstlevel of fluid pressure activates said first sealing mechanism to setsaid first sealing mechanism in said well; (5) a second fluid flowpassageway within said housing and including an initially blocked fluidport opening to the interior of said tubular housing, said blocked fluidport being opened to said tubular housing interior during activation ofsaid first sealing means; and (6) second activation means responsive tofluid pressure in excess of the pressure required to activate the secondsealing mechanism to isolate the said selected first zone from the wellbore upstream of said selected first zone and thereafter, uponapplication of additional pressure within the tubular housing, to fullyopen said treatment port for transmission of a treating fluid withinsaid tubular housing and into said selected first zone. 2) The apparatusof claim 1, further comprising in each of said modules positioned insaid well upstream of the module for isolating the selected first zoneto be treated from a second zone to be treated, full bore valving meansinitially positioned on said housing in an open position allowing fluidflow thereacross, and shiftable to a closed position in response tomechanical manipulation of said tubular workstring, whereby fluid flowacross said valving means in said housing is sealingly blocked. 3) Asingle trip, full bore method for treating a plurality of zones within asubterranean well, comprising the steps of: (a) introducing into thewell a tubular workstring comprising: (1) a tubular housing carried onsaid workstring and including a first fluid passageway therethrough; (2)a plurality of zone isolation modules in securing relationship with saidworkstring, each said module being pre-determinedly spaced on saidhousing for operable alignment with a zone in said well to beselectively treated, each said module including: (i) a tubular housingmember including a treatment fluid port therein and including aselectively communicable control chamber; (ii) first and second sealingmechanisms on said tubular housing for isolating a selected first zoneto be treated from another portion of said well; (iii) a first full borevalving mechanism initially positioned within said housing in a fullbore open position and selectively activatable to a closed positionblocking fluid under pressure from being transmitted within said tubularhousing and across said valving member; (iv) first activation means forsaid first full bore valving means initially responsive to a first levelof fluid pressure applied through said workstring and into said housingmember and shiftable from a first inactive position to a secondactivated position, whereby said port is opened to place said chamber influid communication with said first fluid passageway of said tubularhousing, and further whereby fluid pressure within said housing memberabove the said first level of fluid pressure activates said firstsealing mechanism to set said first sealing mechanism in said well; (v)a second fluid flow passageway within said housing and including aninitially blocked fluid port opening to the interior of said tubularhousing, said blocked fluid port being opened to said tubular housinginterior during activation of said first sealing means; and (vi) secondactivation means responsive to fluid pressure in excess of the pressurerequired to activate the second sealing mechanism to isolate the saidselected first zone from the well bore upstream of said selected firstzone and thereafter, upon application of additional pressure within thetubular housing, to fully open said treatment port for transmission of atreating fluid within said tubular housing and into said selected firstzone; (b) increasing pressure in said tubular workstring and saidtubular housing to a first level of fluid pressure to manipulate saidfirst full bore valving mechanism to closed position and tosimultaneously open said port; (c) further increasing pressure in saidtubular workstring and said tubular housing above the first level ofpressure to activate the first sealing mechanism to set said sealingmechanism in the well and to simultaneously unblock and open saidblocked fluid port; (d) further increasing pressure in said tubularworkstring and said tubular housing to activate the second sealingmechanism to sealing position in the well to isolate the said selectedfirst zone from the wellbore upstream of said selected first zone; and(e) further increasing fluid pressure in the tubular workstring and saidtubular housing to fully open the treatment port for transmission of atreating fluid within said tubular housing and into said selected firstzone.